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Double Eagle Petroleum Company 10-Q 2011 Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
(Mark One)
For the quarterly period ended June 30, 2011
or
For the transition period from to
Commission File Number 1-33571
DOUBLE EAGLE PETROLEUM CO.
(Exact name of registrant as specified in its charter)
303-794-8445
(Registrant’s telephone number, including area code) None
(Former name, former address, and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated
filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of
the latest practicable date.
DOUBLE EAGLE PETROLEUM CO.
FORM 10-Q TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION
DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
The accompanying notes are an integral part of the consolidated financial statements.
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DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
The accompanying notes are an integral part of the consolidated financial statements.
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DOUBLE EAGLE PETROLEUM CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of dollars)
(Unaudited)
The accompanying notes are an integral part of the consolidated financial statements.
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DOUBLE EAGLE PETROLEUM CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)
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The components of accumulated other comprehensive income were as follows:
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The terms “Double Eagle”, “Company”, “we”, “our”, and “us” refer to Double Eagle Petroleum Co. and
its subsidiaries, as a consolidated entity, unless the context suggests otherwise. Unless the
context suggests otherwise, the amounts set forth herein are in thousands, except units of
production, ratios, and share or per share amounts.
FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the
Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance
on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this Form 10-Q that address
activities, events or developments that we expect, believe or anticipate will or may occur in the
future are forward-looking statements. These forward-looking statements are based on assumptions
which we believe are reasonable based on current expectations and projections about future events
and industry conditions and trends affecting our business. However, whether actual results and
developments will conform to our expectations and predictions is subject to a number of risks and
uncertainties that, among other things, could cause actual results to differ materially from those
contained in the forward-looking statements, including without limitation the Risk Factors set
forth in Part I, “Item 1A. Risk Factors” in our Form 10-K for the year ended December 31, 2010 and
the following factors:
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We also may make material acquisitions or divestitures or enter into financing transactions. None
of these events can be predicted with certainty and the possibility of their occurring is not taken
into consideration in the forward-looking statements.
New factors that could cause actual results to differ materially from those described in
forward-looking statements emerge from time to time, and it is not possible for us to predict all
such factors, or the extent to which any such factor or combination of factors may cause actual
results to differ from those contained in any forward-looking statement. We assume no obligation to
update publicly any such forward-looking statements, whether as a result of new information, future
events, or otherwise.
Business Overview and Strategy
We are an independent energy company engaged in the exploration, development, production and sale
of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States.
We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. From 1995 to
2006, our common stock was publicly traded on the NASDAQ Capital Market under the symbol “DBLE”.
In December 2006, our common stock began trading on the NASDAQ Global Select Market under the same
symbol. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued on the NASDAQ
Capital Market under the symbol “DBLEP” in July 2007 and began trading on the NASDAQ Global Select
Market in September 2007. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver,
Colorado 80202, telephone number (303) 794-8445. Our website is www.dble.com.
Our objective is to increase long-term shareholder value by profitably growing our reserves,
production, revenues, and cash flow by focusing primarily on: (i) new coal bed methane gas
development drilling; (ii) enhancement of existing production wells and field facilities on
operated and non-operated properties in the Atlantic Rim; (iii) continued participation in the
development of tight sands gas wells at the Mesa Fields on the Pinedale Anticline; (iv) expansion
of our midstream business; (v) pursuit of high quality exploration and strategic development
projects with potential for providing long-term drilling inventories that generate high returns,
including the Niobrara formation in the Atlantic Rim and other properties in which we have
interests and (vi) selectively pursuing strategic acquisitions.
The operations in the Pinedale Anticline and Atlantic Rim operate under federal exploratory unit
agreements between the working interest partners. Unitization is a type of sharing arrangement by
which owners of operating and non-operating working interests pool their property interests in a
producing area to form a single operating unit. Units are designed to improve efficiency and
economics of developing and producing an area. The share that each interest owner receives is
based upon the respective acreage contributed by each owner in the participating area (“PA”) that
surround the producing wells as a percentage of the entire acreage of the PA. The PA, and the
associated working interest, will change as more wells and acreage are added to the PA.
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OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY
Liquidity and Capital Resources
We believe that the amounts available under our $75 million credit facility ($60 million borrowing
base), combined with our net cash from operating activities, will provide us with sufficient funds
to meet future financial covenants, develop new reserves, maintain our current facilities, and
complete our 2011 capital expenditure program (see “Capital Requirements” on the following page).
Depending on the timing and amounts of future projects, we may be required to seek additional
sources of capital. We can provide no assurance that we will be able to do so on favorable terms
or at all. The Company currently has an effective Form S-3 shelf registration statement on file
with the SEC, which has $150 million of securities available for issuance and provides us the
ability to raise additional funds through private placements or registered offerings of equity. We
also may be required to secure additional debt.
Information about our financial position is presented in the following table:
During the six months ended June 30, 2011, our working capital increased to $10,388 compared to
$7,477 at December 31, 2010. The higher working capital is primarily the result of a decrease in
our accounts payable and accrued liabilities balances. Our accounts payable and accrued expense
balance was lower in 2011 due to the timing of drilling activity in the Pinedale Anticline and our year-end 2010 balance included additional capital billings related to a
PA adjustment at our non-operated Atlantic Rim properties. We also had greater cash and cash
equivalents on hand at June 30, 2011. This was offset somewhat by a decrease in our current assets
from price risk management due to the settlement of derivative contracts in the first six months of
2011 and higher production taxes.
Cash flow activities
The table below summarizes our cash flows for the six months ended June 30, 2011 and 2010,
respectively:
During the six months ended June 30, 2011, net cash provided by operating activities was $11,612,
compared to $10,718 in the same prior-year period. The primary sources of cash during the six
months ended June 30, 2011 were $2,062 of net income, which was net of non-cash charges of $9,474
related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, and
non-cash stock-based compensation expense of $525. In addition, in the first six months of 2011,
we had an increase of $1,238 in the provision for deferred income taxes, which we do not expect to
have to pay in the near future due to our NOL carryforwards. We realized a higher natural gas
price in the first half of 2011, as compared to 2010 due to our hedging program. This additional
cash flow allowed us to use more cash to reduce our accounts payable and accrued expense balance in
the six months ended June 30, 2011.
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During the six months ended June 30, 2011, net cash used in investing activities was relatively
constant, totaling $7,185 in the six months ended June 30, 2011 and $7,084 in the same prior-year
period. Our capital expenditures in the first six months of 2011 primarily related to non-operated
drilling in the Pinedale Anticline.
During the six months ended June 30, 2011, we had net cash used by financing activities of $2,150,
as compared to $5,124 in the same prior-year period. In the first six months of 2011, we
maintained the current debt balance throughout the period, whereas in 2010, we repaid $3,000 of
the outstanding balance on credit facility. We expended cash in the first half of 2011 and 2010 to
make our quarterly dividend payments totaling $1,862 in each period. Dividends are expected to
continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of
$931 per quarter.
Credit Facility
At June 30, 2011, we had a $75 million credit facility in place, with $60 million borrowing base.
The credit facility is collateralized by our oil and gas producing properties and other assets. As
of June 30, 2011, the outstanding balance on our credit facility was $32,000. The interest rate as
of June 30, 2011, calculated in accordance with the agreement, was 2.87%, compared to an interest
rate of 4.5% at June 30, 2010. For the three months ended June 30, 2011 and 2010, we incurred
interest expense of $232 and $353, respectively, related to the credit facility and $558 and $713
for the six months ended June 30, 2011 and 2010, respectively. We capitalized interest costs of
$29 and $37 for the three months ended June 30, 2011 and 2010, respectively, and $64 and $87 for
the six months ended June 30, 2011 and 2010, respectively.
In July 2011, we entered into a $30 million fixed rate swap contract with a third party as a hedge
against the floating interest rate on our credit facility. Under the hedge contract terms, we have
effectively locked in the Eurodollar LIBOR portion of the interest calculation at approximately
0.578% for a portion of our outstanding debt. Based upon our debt level at June 30, 2011, our
interest rate would be fixed at approximately 3.08% for a $30 million tranche of our outstanding
debt. The swap contract is effective July 6, 2011 through December 31, 2012.
We are subject to certain financial and non-financial covenants with respect to the above credit
facility, including requirements to maintain (i) a current ratio, as defined in the agreement, of
at least 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items
(“EBITDAX”) to interest plus dividends, of greater than 1.5 to 1.0; and (iii) a funded debt to
EBITDAX ratio of less than 3.5 to 1.0. As of June 30, 2011, we were in compliance with all
covenants under the credit facility. If we violate any of the covenants, and we are unable to
negotiate a waiver or amendment thereof, the lender would have the right to declare an event of
default, terminate the remaining commitment and accelerate all principal and interest outstanding.
Our borrowing base is subject to redetermination each April 1 and October 1, beginning October 1,
2011.
Capital Requirements
For 2011, we have budgeted approximately $30 million for our development and exploration programs,
which include our assets in the Atlantic Rim and Pinedale Anticline. We intend to drill in the
Atlantic Rim in the second half of 2011, with 14 coal bed methane (“CBM”) production wells within
the Catalina Unit. We expect to participate in approximately 16 new wells at the Mesa Units. We
also have allocated capital in our 2011 capital budget for one exploratory well into the Niobrara
formation in the Atlantic Rim. We are still waiting for permits for this well. We expect to fund
our 2011 capital expenditures with cash provided by operating activities and funds made available
through our credit facility. Our 2011 capital budget does not include the impact of potential
future exploration projects or possible acquisitions, which we continually evaluate.
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Contractual Obligations
The impact that our contractual obligations as of June 30, 2011 are expected to have on our
liquidity and cash flows in future periods is:
Off-Balance Sheet Arrangements
We do not participate in transactions that generate relationships with unconsolidated entities or
financial partnerships. Such entities are often referred to as structured finance or special
purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established
for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or
limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any
of the periods presented.
RESULTS OF OPERATIONS
Three months ended June 30, 2011 compared to the three months ended June 30, 2010
Oil and gas sales volume and price comparisons
For the three months ended June 30, 2011, oil and gas sales increased 50% to $11,393, as compared
to the three months ended June 30, 2010. The increase is largely attributed to cash we received
upon settlement of our cash flow hedge, totaling $2,252 for the three months ended June 30, 2011.
In addition, the average CIG market price, which is the index on which most of our gas volumes are
sold, rose 6% from the three months ended June 30, 2010 and production volumes increased 3%, both
of which also resulted in higher oil and gas sales.
Our average realized natural gas price increased 20% to $4.80 for the three months ended June 30,
2011, as compared to the three months ended June 30, 2010. We calculate our average realized
natural gas price by summing (1) production revenue received from third parties for the sale of our
gas, which is included within oil and gas sales on the consolidated statements of operations; (2)
settlement of our cash flow hedges included within oil and gas sales on the consolidated statement
of operations; and (3) realized gain/ (loss) on our economic hedges, which is included within price
risk management activities, net on the consolidated statements of operations, totaling $168 and
$1,666, for the three months ended June 30, 2011 and 2010, respectively.
Our total net production increased 3% to 2,318 MMcfe for the quarter ended June 30, 2011 as
compared to 2,247 MMcfe for the three months ended June 30, 2010. We experienced an increase in
production volumes at the Sun Dog and Doty Mountain Units, which offset a production decline at the
Catalina Unit, as discussed below.
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During the three months ended June 30, 2011, our total average daily net production at the Atlantic
Rim increased 8% to 19,053 Mcfe, as compared to 17,565 Mcfe during the same prior-year period. Our
Atlantic Rim production comes from three operating units, the Catalina Unit, the Sun Dog Unit and
the Doty Mountain Unit. The Catalina Unit is operated by the Company.
Average daily net production in the Pinedale Anticline remained relatively constant quarter over
quarter, totaling 5,052 Mcfe for the three months ended June 30, 2011, as compared to 5,053 Mcfe in
the same prior-year period. The operator brought seven new wells on-line for production during the
quarter. The operator at the Mesa Units has informed us that it expects to complete 10 additional
wells over the next two quarters. In addition, the operator has indicated that it expects to begin
drilling 16 additional wells in 2011.
Transportation and gathering revenue
During the three months ended June 30, 2011, transportation and gathering revenue decreased 13% to
$1,221 from $1,401 for the three months ended June 30, 2010. We receive fees for gathering and
transporting third party gas through our intrastate gas pipeline, which connects the Catalina Unit
with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The decrease
in revenue is due to the lower production volume at the Catalina Unit.
Price risk management activities, net
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $2,068 for
the three months ended June 30, 2011, as compared to a gain of $103 for the same prior-year period.
The net gain consisted of an unrealized non-cash gain of $1,900, which represents the change in
the fair value on our economic hedges at June 30, 2011, based on the expected future prices of the
related commodities, and a net realized gain of $168 related to the cash settlement of some of our
economic hedges.
Oil and gas production expenses and depreciation, depletion and amortization
Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as
stated on the consolidated statements of operations, by total production volumes during the period.
This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern
Washakie Midstream LLC, which are eliminated in consolidation. During the three months ended June
30, 2011, well production costs increased 15% to $2,769, as compared to $2,397 during the same
prior-year period, and production costs in dollars per Mcfe increased 11%, or $0.12 to $1.19, as
compared to the same prior-year period. The increase in production costs was driven by additional
production costs from the Sun Dog and Doty Mountain Units resulting from our increased working
interests at these properties, which was purchased in July 2010. Because production from the Sun
Dog and Doty Mountain Units, which have historically yielded lower margins than many of our
properties, made up a larger percentage of our total production during the 2011 period, we also
experienced an increase in production costs on a per Mcfe basis. This increase in production costs
at the Sun Dog and Doty Mountain Units was partially offset by lower repair and maintenance costs
at the Catalina Unit.
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Depreciation, depletion, and amortization (“DD&A”) for the quarter ended June 30, 2011 increased 4%
to $4,718, as compared to $4,530 in the same prior-year period, and depletion and amortization
related to producing assets also increased 4% to $4,612 as compared to $4,428 in the same
prior-year period. The increase in DD&A expense was primarily driven by higher production volumes.
Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased
1%, or $0.02, to $1.99 as compared to the same prior-year period.
Pipeline operating costs
During the three months ended June 30, 2011, pipeline operating costs increased 5% to $1,020 from
$971 for the three months ended June 30, 2010.
General and administrative expenses
General and administrative expenses decreased 2% to $1,362 for the three months ended June 30,
2011, as compared to $1,392 for the three months ended June 30, 2010. During the second quarter of
2011, we recovered from our insurance company approximately $101 of legal fees related to
litigation resulting from our 2009 Petrosearch acquisition. This was offset by a $45 increase in
bad debt expense and a $27 increase in director fees due to the addition of one independent
director in the first quarter of 2011.
Income taxes
We recorded income tax expense of $1,342 during the three months ended June 30, 2011, as compared
to an income tax benefit of $512 during the same prior-year period. Our effective tax rate for the
three months ended June 30, 2011 was 37.55% compared to 36.0% for the second quarter of 2010. Our
effective tax rate was higher in the 2011 period due to an increase in the proportion of permanent
income tax differences related to stock option expense as compared to net income and an increase in
non-deductible DD&A expense. Although we expect to continue to generate losses for federal income
tax reporting purposes, our operations have resulted in a deferred tax position required under
generally accepted accounting principles. We expect to recognize deferred income tax expense on
taxable income for the remainder of 2011 at an expected federal and state rate of approximately
35.2%.
Six months ended June 30, 2011 compared to the six months ended June 30, 2010
Oil and gas sales volume and price comparisons
For the six months ended June 30, 2011, oil and gas sales increased 20% to $22,303, as
compared to $18,657 during the first six months of 2010. The increase is attributed to our hedging
program, which provided cash of $4,594 from the settlement of our cash flow hedges during the first
six months of 2011. In addition, we experienced a 2% increase in production volumes in the first
six months of 2011 as compared to the same prior-year period. These increases were offset by a 6%
decrease in the average CIG market price, which is the index on which most of our gas volumes are
sold.
Our average realized natural gas price increased 11% to $4.82 for six months ended June 30, 2011,
as compared to the first six months of 2010. Despite the decrease in the average CIG market price
during the 2011 period, we realized a higher natural gas price as a result of our hedging program.
In addition to the $4,594 of cash flow hedge settlements included in oil and gas sales noted above,
we also realized settlements on our economic hedges totaling $511 during the 2011 period. For the
six months ended June 30, 2010 our hedges accounted for a total of $1,443.
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Our total net production increased 2% to 4,572 MMcfe for the six months ended June 30, 2011
compared to 4,489 MMcfe for the same prior year period. We experienced an increase in production
volumes at the Sun Dog and Doty Mountain Units, which offset the production decline at the Catalina
Unit, as discussed below.
During the six months ended June 30, 2011, average daily net production at the Atlantic Rim
increased 5% to 18,830 Mcfe, as compared to 17,911 Mcfe during the same prior-year period, which is
further broken out below:
Average daily net production in the Pinedale Anticline was relatively constant for the six months
ended June 30, 2011, totaling 5,010 Mcfe per day, as compared to 5,034 Mcfe in the same prior-year
period. The operator brought an additional seven wells on-line throughout the second quarter of
2011. The operator at the Mesa Units has informed us that it expects to complete 10 additional
wells over the next two quarters. In addition, the operator has indicated that it expects to begin
drilling 16 more wells in 2011.
Transportation and gathering revenue
During the six months ended June 30, 2011, transportation and gathering revenue decreased 15% to
$2,453 from $2,889. We receive fees for gathering and transporting third-party gas through our
intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned
by Southern Star Central Gas Pipeline, Inc. The decrease in revenue is due to the lower production
volume at the Catalina Unit.
Price risk management activities, net
We recorded a net gain on our derivative contracts not designated as cash flow hedges of $929 for
the six months ended June 30, 2011, as compared to a gain of $7,925 for the six months ended June
30, 2010. The net gain consisted of an unrealized non-cash gain of $418, which represents the
change in the fair value on our economic hedges at June 30, 2011, based on the future expected
prices of the related commodities, and a net realized gain of $511 related to the cash settlement
of some of our economic hedges.
Oil and gas production expenses, and depreciation, depletion and amortization
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During the six months ended June 30, 2011, well production costs increased 23% to $5,343, as
compared to $4,339 during the same prior-year period, and production costs in dollars per Mcfe
increased 21%, or $0.20 to $1.17, as compared to the same prior-year period. The increase in
production costs in total was driven by additional production costs from the Sun Dog and Doty
Mountain Units resulting from our increased working interests at these properties. In addition,
because production from the Sun Dog and Doty Mountain Units, which have historically yielded lower
margins than many of our properties, made up a larger percentage of our total production during the
2011 period, we experienced an increase in production costs on a per Mcfe basis.
DD&A increased 3% to $9,391 for the six months ended June 30, 2011, as compared to $9,097 for the
six months ended June 30, 2010, and depletion and amortization related to producing assets also
increased 4% to $9,180 as compared to $8,866 in the same prior-year period. The increase in DD&A
expense was primarily driven by higher production volumes. Expressed in dollars per Mcfe,
depletion and amortization related to producing assets increased 2%, or $0.04, to $2.01 as compared
to the same prior-year period.
Pipeline operating costs
During the six months ended June 30, 2011, pipeline operating costs decreased to $2,001 from $2,119
as compared to the same prior-year period.
General and administrative expenses
General and administrative expenses remained relatively constant period over period, totaling
$2,920 and $2,925 for the six months ended June 30, 2011 and 2010, respectively. During the second
quarter o f 2011, we recovered from our insurance company approximately $101 of legal fees related
to litigation resulting from our 2009 Petrosearch acquisition. In addition, we realized a $77
decrease in audit and tax fees, a $78 decrease in legal fees and a $49 decrease in our directors
and officers insurance as compared to the same prior year period. These decreases were offset by a $69 increase
related to our Board of Directors expense due to the expansion of our Board and expenses incurred
related to Board training and conferences, an increase in bank fees of $56 due to an increase in
the unused portion of our credit facility and in 2010 we had recovered an outstanding receivable
that had previously been written off totaling $155.
Income taxes
During the six months ended June 30, 2011, we recorded income tax expense of $1,238 compared to
income tax expense of $2,945 during the same prior-year period. Our effective tax rate for the six
months ended June 30, 2011 was 37.55% compared to 36.0% for the second quarter of 2010. Our
effective tax rate was higher in the 2011 period due to an increase in the proportion of permanent
income tax differences related to stock option expense as compared to net income and an increase in
non-deductible DD&A expense. Although we expect to continue to generate losses for federal income
tax reporting purposes, our operations have resulted in a deferred tax position required under
generally accepted accounting principles. We expect to recognize deferred income tax expense on
taxable income for the remainder of 2011 at an expected federal and state rate of approximately
35.2%.
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CONTRACTED VOLUMES
Changes in the market price of oil and natural gas can significantly affect our profitability and
cash flow. We have entered into various derivative instruments to mitigate the risk associated
with downward fluctuations in the natural gas price. Historically these derivative instruments
have consisted of fixed delivery contracts, swaps, options and costless collars. The duration and
size of our various derivative instruments varies, and depends on our view of market conditions,
available contract prices and our operating strategy.
Our outstanding derivative instruments as of June 30, 2011 are summarized below (volume and daily
production are expressed in Mcf):
Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional
discussion on the accounting treatment of our derivative contracts.
Subsequent to the end of the period ended June 30, 2011, we entered into a $30 million fixed rate
swap contract with a third party as a hedge against the floating interest rate on our credit
facility. which fixes the Eurodollar portion of our interest rate calculation at approximately
0.578%. The contract is in place through December 31, 2012.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for
the year ended December 31, 2010, and to the Notes to the Consolidated Financial Statements
included in Part I, Item 1 of this report.
Commodity Price Risks
Our major market risk exposure is in the pricing applicable to our natural gas and oil production.
Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices
applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been
volatile and unpredictable for several years. The prices we receive for production depend on many
factors outside of our control. For the three months ended June 30, 2011, our income before income
taxes would have increased by $548 for each $0.50 increase per Mcf in natural gas prices and
decreased by $297 for each $0.50 decrease per Mcf in natural gas prices due to the contracted volumes discussed above. Our income taxes would have
increased $6 for each $1.00 change per Bbl in crude oil prices for the three months ended June 30,
2011.
The primary objective of our commodity price risk management policy is to preserve and enhance the
value of our equity gas production. We have entered into natural gas derivative contracts to
manage our exposure to natural gas price volatility. Our derivative instruments typically consist
of forward sales contracts, swaps and costless collars, which allow us to effectively “lock in” a
portion of our future production of natural gas at prices that we consider favorable to us at the
time we enter into the contract. These derivative instruments which have differing expiration
dates, are summarized in the table presented above under “Contracted Volumes”.
Interest Rate Risks
At June 30, 2011, we had a total of $32,000 outstanding under our $75 million credit facility ($60
million borrowing availability). We pay interest on outstanding borrowings under our credit
facility at interest rates that fluctuate based upon changes in our levels of outstanding debt and
the prevailing market rates. The average interest rate for the three months ended June 30, 2011,
calculated in accordance with the agreement, was 2.87%. Because the interest rate is variable and
reflects current market conditions, the carrying value approximates the fair value. Assuming no
change in the amount outstanding at June 30, 2011, the annual impact on interest expense for every
1.0% change in the average interest rate would be approximately $320 before taxes. Any balance
outstanding on the credit facility matures on January 31, 2013.
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In July 2011, we entered into a $30 million fixed rate swap contract with a third party as a hedge
against the floating interest rate on our credit facility. Under the hedge contract terms, we have
effectively locked in the Eurodollar LIBOR portion of the interest calculation at approximately
0.578% for a portion of our outstanding debt. Based upon our debt level at June 30, 2011, this
would result in a fixed interest rate of 3.08% for a $30 million tranche of our outstanding debt.
The contract is effective July 6, 2011 through December 31, 2012.
In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management, including our Chief
Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting
Officer), of the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, our Chief
Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting
Officer) have concluded that our disclosure controls and procedures are effective to ensure that
information we are required to disclose in reports that we file or submit under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms.
There has been no change in our internal control over financial reporting that occurred during the
quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
From time to time, the Company is involved in various legal proceedings, including the matters
discussed below. These proceedings are subject to the uncertainties inherent in any litigation.
The Company is defending itself vigorously in all such matters, and while the ultimate outcome and
impact of any proceeding cannot be predicted with certainty, management believes that the
resolution of any proceeding will not have a material adverse effect on the Company’s financial
condition or results of operations.
On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch Energy
Corporation (“Petrosearch”) prior to the Company’s acquisition (the “Acquisition”) of Petrosearch
pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a
claim in the District Court for the Southern District of New York against Petrosearch, the Company,
and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied
dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection
with the Acquisition, that the defendants violated various sections of the Securities Act of 1933
and the Securities Exchange Act of 1934, and that the defendants caused other damages to the
stockholders of Petrosearch. The plaintiff was seeking monetary damage. On March 31, 2011, the
District Court judge dismissed the case. The plaintiff filed a notice of appeal on April 29, 2011,
which preserves the plaintiff’s right to appeal.
There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of
our 2010 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we
incorporate by reference herein.
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The following exhibits are filed as part of this report:
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
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EXHIBIT INDEX
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